1. Field of the Invention
This invention relates in general to methods and devices for monitoring the corrosion characteristics of tubing fluid in a producing well, and in particular to an improved method and device for monitoring the corrosion characteristics of well tubing fluids by installing a monitoring device downhole in a side pocket mandrel.
2. Description of the Prior Art
Oil and gas wells normally contain several concentric metal conduits extending from the bottom of the well to the surface. The inner conduits are known as well tubing, and the outermost conduit is known as the well casing. Various fluids flow, or are pumped, upwardly or downwardly within the innermost tubing or within the annular spaces between conduits.
Fluid within the tubing, i.e., tubing fluid, may be highly corrosive to the steel tubing. For example, carbon dioxide and hydrogen sulfide are common corrosives in many oil and gas wells. Tubing failure because of corrosion may necessitate an extensive workover. In order to combat corrosion, various chemicals may be injected into the well or into the producing formation to inhibit the corrosive action of the well fluids on the steel tubing.
The injection of corrosion inhibitors into a well has at times been unsuccessful because of the failure of the solution to completely coat the metal to be protected. U.S. Pat. No. 3,385,358 (Shell) shows a monitoring device used to inspect for total coverage. A tracer material is included in the inhibitor solution prior to injection. Then, after injection, a radioactivity detector is lowered into the well on a wireline to monitor the coverage of the inhibitor solution.
Another method of monitoring the effectiveness of corrosion inhibitors is to insert metal coupons into the fluid for a specified time and then inspect the coupons. A method and apparatus for inserting coupons into a surface pipeline is described in U.S. Pat. No. 4,275,592 (Atwood). That method is excellent for monitoring fluid in a surface pipeline, but the corrosive effects of the fluid in the surface pipeline may be much different from the corrosive effects of the fluid downhole.
Corrosion monitoring coupons can be placed downhole by lowering a coupon carrier down the tubing string on a wire line. However, the device partially blocks the flow of fluid through the tubing, and the device must be removed before other tools can be run down the tubing.
U.S. Pat. No. 4,501,323 (Lively et al.) shows a method for monitoring fluids downhole by installing corrosion coupons within a carrier, which is then placed within a side pocket mandrel. Ports and passages allow casing fluid or tubing fluid to communicate with various coupons. The carrier is left within the side pocket mandrel for a specified time period. The carrier is then removed from the well, and the coupons are inspected.
U.S. Pat. No. 4,483,397 (Gray) shows a similar method and apparatus for monitoring tubing fluid downhole in an oil or gas well. Corrosion coupons are installed in a carrier which is placed in a side pocket mandrel. The outer surface of the mandrel is free of apertures, so only tubing fluid can be monitored. Ports and passages in the side pocket and in the carrier allow tubing fluid to communicate with the coupon. After the carrier has been in the side pocket for a specified time period, the carrier is removed from the well, and the coupons are inspected.